The present invention relates in general to pumps finding particular efficacious use in petroleum wells, and, more in particular, to such pumps that are electrically operated and have centrifugal stages.
Submersible petroleum pumps have been in use for some time. These pumps reside downhole in a petroleum well in the vicinity of the petroleum bearing formation. Typically, the pumps force petroleum from the formation to the surface of the well. Other applications of such pumps include their use in formation flooding for secondary recovery of petroleum.
Centrifugal pumps are pumps driven in rotation. An impeller of the pump rotates within a casing. Fluid enters the pump at an eye of the impeller. Vanes of the impeller impart energy from the prime mover, here an electric motor, to the fluid flowing through the impeller in channels between the vanes. Conventionally, the energy content of the fluid is expressed as head and has the units of force times length divided by mass. Centrifugal pumps are chracterized by imparting a significant radial component to the fluid they pump. Axial flow pumps, by contrast, do not impart a significant radial component to fluid passing through them. Centrifugal pumps are also characterized by low flow rates and high head increase. Axial flow pumps are characterized by low head increase and high flow rates.
The specific speed of a pump relates three performance parameters of the pump as follows: EQU N.sub.s =N(Q).sup.1/2 /(H).sup.3/4
where:
N.sub.s =specific speed PA1 N=rotational speed of the pump (1/t) PA1 Q=flow rate through the pump (l.sup.3 /t) PA1 H=head (l.sup.2 /t.sup.2) PA1 t=time (e.g., seconds) PA1 l=length (e.g., meters)
A characteristic specific speed for optimum efficiency exists for each type of pump. For a centrifugal pump, the specific speed at optimum efficiency is low with respect to the specific speed of an axial flow pump. Centrifugal pumps develop considerable head. On the other hand, their flow passages are small. With the small passages, friction losses become serious at high flow rates. Accordingly, flow rates are comparatively low for efficient centrifugal pumps.
Many petroleum wells produce only a small quantity of petroleum. By way of example, some petroleum wells produce only 100 to 200 barrels of petroleum per day. For electric motor-driven centrifugal pumps used in downhole locations, this flow rate results in specific speeds that are far below optimum. The motor speed being constant, the only variable that can be adjusted is head to maintain adequate specific speeds. But dropping the head requires a reduction in the diameter of the impeller, which is undesirable, and an increase in the number of required stages, which is also undesirable. Diameter reduction reduces the startup head capacity available and eliminates standardization of pump stage units.
Downhole centrifugal pumps cannot practically be made axially short to restrict channel capacity to match low flow rates. The spacing between the pump's impeller and casing must reduce as the size of the pumps drops. The required spacing in small pumps is too difficult to meet on a production basis. Furthermore, resultant vane length attending a design with low flow rates becomes too long, and friction losses increase as a result. Very significant percentage increases in disc friction or windage with respect to power befalls too great a centrifugal stage size reduction. Circulation loss between the discharge and inlet also increases and is a factor.
These factors result in the impracticality of very low flow rates in centrifugal pumps.
Centrifugal pumps operate efficiently and reliably when the flow rate of the pumps is on the order of 600 barrels per day. When the petroleum well flows on the order of 150 barrels per day, efficient and reliable operation of the submersible electrically powered centrifugal pumps becomes impossible.
Unless such pumps operate within their design range, a substantial risk of motor failure exists. Motor failure not only shuts down a well, but requires considerable time and effort to remedy. The requirement of pulling a pump from a well hundreds or thousands of feet deep illustrates this. With the pump operating at low efficiency, a risk that no pumping at all will occur exists. When this happens and no fluid passes through the pump, motor failure from heating can occur.
Even with overload detectors it is not possible to always sense in time a condition where motor failure can occur. While operating at very low flows a slight rise in head results in a dramatic drop in flow. During this time the amount of the energy expended by the motor remains very nearly the same. Accordingly, motor cooling suffers. Moreover, the pump can be in a very deep well and the time lag between sensing a dangerous condition at the surface and turning off the motor may be too long to save the motor.